HOUSTON--(BUSINESS WIRE)--Black Stone Minerals, L.P. (NYSE: BSM) (“Black Stone Minerals,” “Black
Stone,” or “the Partnership”) today announces its financial and
operating results for the fourth quarter and full year of 2016 and
provides guidance for 2017.

Highlights

Full year 2016 production of 31.7 MBoe/d, at the high end of annual
guidance.

Reported 2016 net income of $20.2 million and Adjusted EBITDA of
$262.3 million.

Proved reserves at year-end 2016 totaled 63.4 MMBoe, an increase of
27% over prior year driven largely by development activity in the East
Texas Haynesville/Bossier play, and were approximately 78% proved
developed producing.

Production for 2017 expected to average 35.0 – 37.0 MBoe/d, a 14%
increase over 2016 average daily volumes at the mid-point of guidance.

Entered into a farmout agreement in February 2017 that will
substantially reduce Black Stone’s future working interest capital
requirements and generate additional royalty income, while
facilitating continued development of the Partnership’s East Texas
Haynesville/Bossier acreage.

Management Commentary

“Black Stone had a very solid 2016 and we are off to a strong start in
2017,” stated Thomas L. Carter, Jr., Black Stone Minerals’ President,
Chief Executive Officer, and Chairman. “We grew production in 2016 by
11% and came in at the upper end of our production guidance, which we
had increased mid-year, and we expect to deliver even greater growth in
2017. Our recent acquisitions have added to our core minerals positions
in the Delaware, Midland, and Haynesville plays where we are seeing
robust producer activity, and our recently announced farmout in East
Texas will meaningfully reduce our working interest capital expenditures
going forward and generate greater free cash flow for increased
distributions.”

Mr. Carter continued, “Based on our current initiatives and our
long-term outlook for our diverse mineral portfolio, we are confident
that we will be able to fully replace the declining working interest
production resulting from the farmout agreement with increasing royalty
volumes, which will allow us to deliver long-term production and cash
flow growth. We are well positioned to continue building long-term value
for our unitholders.”

Quarterly Financial and Operating Results

Production

Black Stone Minerals reported average production of 29.8 MBoe/d for the
fourth quarter of 2016, representing an increase of 10% from the
corresponding period in 2015. Mineral and royalty volumes made up 62% of
the Partnership’s total reported volumes in the fourth quarter of 2016.

Reported volumes in the fourth quarter of 2016 were negatively impacted
by production shut-ins estimated at 1.0 MBoe/d for the quarter related
to offset completion work and processing plant downtime in the
Haynesville Shale, as well as by a number of non-recurring items. The
Partnership exited the year at a run-rate of approximately 31.5 MBoe/d,
including the impact of shut-in wells.

Realized Prices, Revenues, and Net Loss

The Partnership’s average realized price per Boe, excluding the effect
of derivative settlements, was $27.29 for the quarter ended December 31,
2016, an increase of 13% from $24.15 per Boe for the corresponding
quarter last year.

Black Stone Minerals reported oil and gas revenues of $74.9 million in
the fourth quarter of 2016, an increase of 24% from $60.2 million in the
fourth quarter of 2015. The increase reflects higher reported production
volumes as well as modestly higher commodity prices compared to the
corresponding period in 2015.

The Partnership reported a loss on commodity derivative instruments of
$24.2 million for the fourth quarter of 2016, which comprised a $5.6
million gain from realized settlements and a $29.8 million unrealized
loss due to the change in value of Black Stone’s derivative positions
during the quarter.

Lease bonus and other income was $6.0 million for the fourth quarter of
2016, compared to $7.0 million for the same period last year.

The Partnership reported a net loss of $7.3 million for the quarter
ended December 31, 2016, compared to a net loss of $49.7 million in the
corresponding period in 2015. Adjusted EBITDA for the fourth quarter of
2016, which reflects the impact of the adverse production impacts
mentioned earlier, was $58.3 million, as compared to $54.0 million for
the fourth quarter of 2015.

2016 Proved Reserves

Estimated proved oil and natural gas reserves at year-end 2016 were 63.4
MMBoe, an increase of 27% from 49.8 MMBoe at year-end 2015, and were
approximately 29% oil and 78% proved developed producing. The discounted
net cash flow of proved reserves discounted at 10% (“PV-10”) was $603.0
million at the end of 2016 as compared to $555.0 million at year-end
2015.

Netherland Sewell & Associates, an independent petroleum engineering
firm, prepared the estimate of Black Stone Minerals’ proved reserves and
PV-10 at December 31, 2016 using reference prices of $42.75 per barrel
of oil and $2.48 per MMBTU of natural gas in accordance with the
applicable rules of the Securities and Exchange Commission. These prices
were adjusted for quality and market differentials, transportation fees,
and in the case of natural gas, the value of natural gas liquids. A
rollforward of proved reserves is presented in the summary financial
tables following this press release.

Financial Position

As of December 31, 2016, Black Stone Minerals had $316.0 million
outstanding under its credit facility. Black Stone Minerals is in
compliance with all financial covenants associated with its credit
facility. The Partnership’s borrowing base at December 31, 2016 was $500
million. Black Stone’s regularly scheduled borrowing base
redetermination is set for April 2017. As of February 27, 2017, $394.0
million was outstanding under the credit facility, which includes
borrowings related to the consummation of recent acquisitions discussed
below and the distribution payment related to the fourth quarter of 2016.

Fourth Quarter 2016 Distributions

As previously announced, the Board of Directors of the general partner
approved a cash distribution of $0.2875 per common unit and $0.18375 per
subordinated unit attributable to the fourth quarter of 2016. The
quarterly distribution coverage ratio was approximately 1.1x for all
classes of units (1.8x for common units). These distributions were paid
earlier today.

Acquisition Activity

The Partnership closed several acquisitions totaling $141.1 million in
2016. These included the $87.6 million acquisition of diverse minerals
from Freeport-McMoRan, the $34.0 million acquisition of mineral assets
in the Wattenberg Field in Colorado, and two smaller transactions in the
Midland Basin. Black Stone has completed multiple transactions to date
in 2017 totaling approximately $58 million, with approximately $43
million and $15 million focused in the Delaware Basin and
Haynesville/Bossier play, respectively. In one transaction, $11.8
million of the purchase price was paid in Black Stone Minerals’ common
units, which marked the first time since going public the Partnership
has directly used its equity in a transaction. Since its IPO in May of
2015, Black Stone has closed on approximately $260 million of
acquisitions.

“We are off to a strong start on the acquisition front already in 2017.
We’ve added acreage in the best part of the Delaware Basin, which we
think is going to get developed very quickly. In the Haynesville, we’re
having some success adding positions around acreage that we already
control in East Texas. We think this will allow us to influence the
development of those assets in a way that will accelerate drilling
activity for the next several years,” commented Mr. Carter. “I am
particularly pleased that we were able to use direct equity in an
acquisition. Having a currency that provides diversification and
liquidity in a tax-efficient manner for potential sellers was one of the
reasons we went public, and I think we’ll be able to do more of this in
the future.”

Farmout of Working Interests

On February 21, 2017, Black Stone announced it had entered into a
farmout agreement that will reduce Black Stone’s future working interest
capital expenditures and will generate additional royalty income through
a retained overriding royalty interest. The farmout covers the
Partnership’s working interests within an approximate 34,000 gross acre
block in San Augustine County, Texas that is currently under development
for the Haynesville/Bossier play. Black Stone expects the farmout
agreement to reduce its capital obligations by approximately $30-$35
million in 2017 and by an average of $40-$50 million annually over the
initial six years covered under the agreement.

Summary 2017 Guidance

Key assumptions in Black Stone Minerals’ 2017 program are as follows:

FY2017

Average daily production (MBoe/d)

35.0 – 37.0

Percentage oil

~25%

Percentage royalty interest

~60%

Lease bonus and other income ($MM)

$25 – $35

Lease operating expense ($MM)

$18 – $22

Production costs and ad valorem taxes (as % of total pre-derivative
O&G revenue)

13% – 15%

Exploration expense ($MM)

$0.5 – $1.5

G&A – cash ($MM)

$41.0 – $43.0

G&A – non-cash ($MM)

$25.0 – $27.0

G&A – TOTAL ($MM)

$66.0 – $70.0

DD&A ($/Boe)

$8.50 – $9.50

Working Interest Participation

Black Stone Minerals expects to invest approximately $50 to $60 million
in its working interest participation program in 2017, the vast majority
of which relates to opportunities in the East Texas Haynesville/Bossier
play. Approximately $40 million relates to 13 wells that were spud in
2016 but will be completed in 2017. Those wells are not covered by the
previously announced farmout agreement, which reduces Black Stone’s
working interest by 80% in the Haynesville/Bossier play within certain
areas in San Augustine County, Texas for wells spud after January 1,
2017. As a result of the farmout, the Partnership expects its annual
capital investment related to these assets going forward to range from
$10 million to $15 million, depending on the actual number of wells
drilled and completed each year.

The Partnership’s working interest production is anticipated to average
approximately 40% of total production in 2017, and decline thereafter to
management's long-term target of less than 20%.

Hedge Position

The Partnership has commodity derivative contracts in place covering a
substantial part of 2017’s anticipated production. Based on the guided
volumes above, approximately 65% of expected oil volumes are hedged at
prices averaging $55.18 per barrel, and approximately 75% of expected
gas volumes are hedged at prices averaging $3.16 per Mcf. The
Partnership has also added hedges covering portions of expected 2018 oil
and natural gas production. More detailed information regarding the
Partnership’s existing hedge position can be found in the Annual Report
on Form 10-K for 2016, which is expected to be filed on or around March
1, 2017.

Subordinated Unit Conversion Outlook

Black Stone’s subordinated units first become eligible for conversion
into common units on March 31, 2019. In recent discussions regarding the
subordinated unit conversion, the Board of Directors has emphasized its
belief in the critical importance of having a strong, growing common
distribution as the Partnership exits the conversion period.
Accordingly, management and the Board recognize that the subordinated
units may need to be converted at a ratio of less than one-to-one to
facilitate the continued growth of the common distribution and have
agreed that decisions pertaining to the conversion of subordinated units
will be made in the context of positioning the common units for future
distribution growth.

Mr. Carter commented, “Our primary goal at Black Stone is to deliver
long-term value to our unitholders, which we believe requires a growing
common distribution. One of the factors affecting our ability to
continue to grow common distributions, in addition to actual
distributable cash flow, is the impact of the conversion of the
subordinated units and the resulting number of total common units
outstanding after conversion. While we are sensitive to the potential
dilution of our subordinated unit holders if conversion takes place at
less than a one-to-one ratio, we and the Board are placing a high
priority on sustained common unit distribution growth.”

Conference Call

Black Stone Minerals will host a conference call and webcast for
investors and analysts to discuss its results for the fourth quarter and
full year of 2016 on Tuesday, February 28, 2017 at 9:00 a.m. Central
Time. To join the call, participants should dial (877) 447-4732 and use
conference code 58697648. A live broadcast of the call will also be
available at http://investor.blackstoneminerals.com.
A recording of the conference call will be available at that site
through March 31, 2017.

Upcoming Investor Relations Events

Members of management from Black Stone Minerals will also be
participating in the following investor events:

EnerCom Dallas Investors Conference – March 2, 2017 in Dallas, Texas.
Management will be participating in one-on-one meetings throughout the
day and is scheduled to present at 10:05 a.m. Central time. A webcast
for this presentation will be available in the Investors section of
the BSM website.

Updated presentation materials, if any, for the aforementioned events
will be made available on the Black Stone Minerals website the day of
the respective event.

About Black Stone Minerals, L.P.

Black Stone Minerals is one of the largest owners of oil and natural gas
mineral interests in the United States. The Partnership owns mineral
interests and royalty interests in over 40 states and 60 onshore basins
in the continental United States. The Partnership also owns and
selectively participates as a non-operating working partner in
established development programs, primarily on its mineral and royalty
holdings. The Partnership expects that its large, diversified asset base
and long-lived, non-cost-bearing mineral and royalty interests will
result in production and reserve growth, as well as increasing quarterly
distributions to its unitholders.

Forward-Looking Statements

This news release includes forward-looking statements. All statements,
other than statements of historical facts, included in this news release
that address activities, events or developments that the Partnership
expects, believes or anticipates will or may occur in the future are
forward-looking statements. Terminology such as “will,” “may,” “should,”
“expect,” “anticipate,” “plan,” “project,” “intend,” “estimate,”
“believe,” “target,” “continue,” “potential,” the negative of such terms
or other comparable terminology often identify forward-looking
statements. Except as required by law, Black Stone Minerals undertakes
no obligation and does not intend to update these forward-looking
statements to reflect events or circumstances occurring after this news
release. You are cautioned not to place undue reliance on these
forward-looking statements, which speak only as of the date of this news
release. All forward-looking statements are qualified in their entirety
by these cautionary statements. These forward-looking statements involve
risks and uncertainties, many of which are beyond the control of Black
Stone Minerals, which may cause the Partnership’s actual results to
differ materially from those implied or expressed by the forward-looking
statements. Important factors that could cause actual results to differ
materially from those in the forward-looking statements include, but are
not limited to, those summarized below:

the Partnership’s ability to execute its business strategies;

the volatility of realized oil and natural gas prices;

the level of production on the Partnership’s properties;

regional supply and demand factors, delays, or interruptions of
production;

the Partnership’s ability to replace its oil and natural gas reserves;
and

the Partnership’s ability to identify, complete, and integrate
acquisitions.

DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS SUBSEQUENT TO INITIAL
PUBLIC OFFERING

(1,324

)

(2,739

)

(5,763

)

(7,522

)

NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND
SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING

$

(8,613

)

$

(51,346

)

$

14,437

$

(108,017

)

ALLOCATION OF NET INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC
OFFERING ATTRIBUTABLE TO:

General partner interest

$

—

$

—

$

—

$

—

Common units

326

(25,824

)

24,669

(54,326

)

Subordinated units

(8,939

)

(25,522

)

(10,232

)

(53,691

)

$

(8,613

)

$

(51,346

)

$

14,437

$

(108,017

)

NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND
SUBORDINATED UNIT:

Per common unit (basic)

$

0.01

$

(0.27

)

$

0.26

$

(0.56

)

Weighted average common units outstanding (basic)

95,725

96,182

96,073

96,182

Per subordinated unit (basic)

$

(0.10

)

$

(0.27

)

$

(0.11

)

$

(0.56

)

Weighted average subordinated units outstanding (basic)

95,180

95,057

95,138

95,057

Per common unit (diluted)

$

0.01

$

0.27

$

0.26

$

(0.56

)

Weighted average common units outstanding (diluted)

95,895

96,182

96,439

96,182

Per subordinated unit (diluted)

$

(0.10

)

$

0.27

$

(0.11

)

$

(0.56

)

Weighted average subordinated units outstanding (diluted)

95,180

95,057

95,394

95,057

DISTRIBUTIONS DECLARED AND PAID SUBSEQUENT TO INITIAL PUBLIC
OFFERING:

Per common unit

$

0.2875

$

0.2625

$

1.1000

$

0.4240

Per subordinated unit

$

0.1838

$

0.2625

$

0.7350

$

0.4240

The following table shows the Partnership’s production, revenues,
realized prices, and expenses for the periods presented.

Three Months EndedDecember 31,

Year EndedDecember 31,

2016

2015

2016

2015

(Unaudited)(Dollars in thousands, except for
realized prices)

Production:

Oil and condensate (MBbls)1

832

897

3,680

3,565

Natural gas (MMcf)1

11,484

9,572

47,498

41,389

Equivalents (MBoe)

2,746

2,492

11,596

10,463

Revenue:

Oil and condensate sales

$

37,801

$

36,954

$

142,382

$

163,538

Natural gas and natural gas liquids sales

37,130

23,219

122,836

116,018

Gain (loss) on commodity derivative instruments

(24,169

)

32,838

(36,464

)

90,288

Lease bonus and other income

5,950

7,029

32,079

23,080

Total revenue

$

56,712

$

100,040

$

260,833

$

392,924

Realized prices:

Oil and condensate ($/Bbl)

$

45.43

$

41.20

$

38.69

$

45.87

Natural gas ($/Mcf)1

$

3.23

$

2.43

$

2.59

$

2.80

Equivalents ($/Boe)

$

27.29

$

24.15

$

22.87

$

26.72

Operating expenses:

Lease operating expense

$

4,576

$

5,043

$

18,755

$

21,583

Production costs and ad valorem taxes

12,163

9,517

35,464

35,767

Exploration expense

2

578

645

2,592

Depreciation, depletion, and amortization

22,833

20,884

102,487

104,298

Impairment of oil and natural gas properties

—

92,886

6,775

249,569

General and administrative

20,926

23,645

73,139

77,175

Other expense:

Interest expense

2,774

888

7,547

6,418

Per Boe:

Lease operating expense (per working interest Boe)

4.35

7.11

4.62

4.32

Production costs and ad valorem taxes

4.43

3.82

3.06

3.42

Depreciation, depletion, and amortization

8.32

8.38

8.84

9.97

General and administrative

7.62

9.49

6.31

7.38

____________

1

As a mineral-and-royalty-interest owner, Black Stone Minerals is
often provided insufficient and inconsistent data on natural gas
liquid ("NGL") volumes by its operators. As a result, the
Partnership is unable to reliably determine the total volumes of
NGLs associated with the production of natural gas on its acreage.
Accordingly, no NGL volumes are included in our reported production;
however, revenue attributable to NGLs is included in natural gas
revenue and the calculation of realized prices for natural gas.

Non-GAAP Financial Measures

EBITDA, Adjusted EBITDA, and cash available for distribution are
non-GAAP supplemental financial measures used by Black Stone Minerals’
management and external users of the Partnership’s financial statements
such as investors, research analysts, and others, to assess the
financial performance of its assets and its ability to sustain
distributions over the long term without regard to financing methods,
capital structure, or historical cost basis.

EBITDA, Adjusted EBITDA, and cash available for distribution should not
be considered an alternative to, or more meaningful than, net income
(loss), income (loss) from operations, cash flows from operating
activities, or any other measure of financial performance presented in
accordance with GAAP as measures of the Partnership’s financial
performance. EBITDA, Adjusted EBITDA, and cash available for
distribution have important limitations as analytical tools because they
exclude some but not all items that affect net income (loss), the most
directly comparable GAAP financial measure. The Partnership’s
computation of EBITDA, Adjusted EBITDA, and cash available for
distribution may differ from computations of similarly titled measures
of other companies.

The following table presents a reconciliation of EBITDA, Adjusted
EBITDA, and cash available for distribution to net income, the most
directly comparable GAAP financial measure, for the periods indicated.

Three Months EndedDecember 31,

Year EndedDecember 31,

2016

2015

2016

2015

(Unaudited)(In thousands)

(Unaudited)(In thousands)

Net income (loss)

$

(7,286

)

$

(49,730

)

$

20,188

$

(101,305

)

Adjustments to reconcile to Adjusted EBITDA:

Add:

Depreciation, depletion and amortization

22,833

20,884

102,487

104,298

Interest expense

2,774

888

7,547

6,418

EBITDA

18,321

(27,958

)

130,222

9,411

Add:

Impairment of oil and natural gas properties

—

92,886

6,775

249,569

Accretion of asset retirement obligations

212

270

892

1,075

Equity-based compensation1

10,018

4,948

43,138

18,000

Unrealized loss on commodity derivative instruments

29,738

—

81,253

—

Less:

Unrealized gain on commodity derivative instruments

—

(16,145

)

—

(27,063

)

Adjusted EBITDA

58,289

54,001

262,280

250,992

Adjustments to reconcile to cash generated from operations:

Add:

Restructuring charges

—

4,208

—

4,208

Incremental general and administrative related to initial public
offering

—

353

—

1,303

Loss on sales of assets, net

—

—

—

—

Less:

Change in deferred revenue

(695

)

(76

)

(870

)

(660

)

Cash interest expense

(2,497

)

(677

)

(6,676

)

(5,483

)

Gain on sales of assets, net

(21

)

(4,853

)

(4,793

)

(4,873

)

Estimated replacement capital expenditures2

(3,750

)

—

(11,250

)

—

Cash generated from operations

51,326

52,956

238,691

245,487

Less:

Cash paid to noncontrolling interests

(28

)

(41

)

(111

)

(208

)

Redeemable preferred unit distributions

(1,324

)

(2,739

)

(5,763

)

(11,562

)

Cash generated from operations available for distribution on common
and subordinated units and reinvestment in our business

$

49,974

$

50,176

$

232,817

$

233,717

____________

1

On April 25, 2016, the Compensation Committee of the Board approved
a resolution to change the settlement feature of certain employee
long-term incentive compensation plans from cash to equity. As a
result of the modification, $10.1 million of cash-settled
liabilities were reclassified to equity-settled liabilities during
the second quarter of 2016.

2

On August 3, 2016, the Board established a replacement capital
expenditures estimate of $15.0 million for the period of April 1,
2016 to March 31, 2017. There was no established estimate of
replacement capital expenditures prior to this period.